The Utility follows accounting principles for rate-regulated entities and collects rates from customers to recover “revenue requirements” that have been authorized by the CPUC or the FERC based on the Utility’s cost of providing service. The Utility’s ability to recover a significant portion of its authorized revenue requirements through rates is generally independent, or “decoupled,” from the volume of the Utility’s electricity and natural gas sales. The Utility records assets and liabilities that result from the regulated ratemaking process that would not be recorded under GAAP for nonregulated entities. The Utility capitalizes and records as regulatory assets costs that would otherwise be charged to expense if it is probable that the incurred costs will be recovered through future rates. Regulatory assets are amortized over the future periods in which the costs are recovered. If costs expected to be incurred in the future are currently being recovered through rates, the Utility records those expected future costs as regulatory liabilities. Amounts that are probable of being credited or refunded to customers in the future are also recorded as regulatory liabilities.

The Utility also records a regulatory balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund. In addition, the Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. These differences have no impact on net income. See “Revenue Recognition” below.

Management continues to believe the use of regulatory accounting is applicable and that all regulatory assets and liabilities are recoverable or refundable. To the extent that portions of the Utility’s operations cease to be subject to cost-of-service rate regulation, or recovery is no longer probable as a result of changes in regulation or other reasons, the related regulatory assets and liabilities are written off.

Cash and cash equivalents consist of cash and short-term, highly liquid investments with original maturities of three months or less. Cash equivalents are stated at fair value. As of December 31, 2023, the Utility also holds $294 million of restricted cash that primarily consists of AB 1054 and SB 901 fixed recovery charge collections that are to be used to service the associated bonds.

The Utility recognizes revenues when electricity and natural gas services are delivered. The Utility records unbilled revenues for the estimated amount of energy delivered to customers but not yet billed at the end of the period. Unbilled revenues are included in Accounts receivable on the Consolidated Balance Sheets. Rates charged to customers are based on CPUC and FERC authorized revenue requirements. Revenues can vary significantly from period to period because of seasonality, weather, and customer usage patterns.

The CPUC authorizes most of the Utility’s revenues in the Utility’s GRCs, which occur every four years. CPUC and FERC rates decouple authorized revenue from the volume of electricity and natural gas sales, so the Utility receives revenue equal to the amounts authorized by the relevant regulatory agencies. As a result, the volume of electricity and natural gas sold does not have a direct impact on PG&E Corporation’s and the Utility’s financial results. The Utility recognizes revenues that have been authorized for rate recovery, are objectively determinable and probable of recovery, and are expected to be collected within 24 months. Generally, electric and natural gas operating revenue is recognized ratably over the year. The Utility records a balancing account asset or liability for differences between customer billings and authorized revenue requirements that are probable of recovery or refund.

The Utility also collects additional revenue requirements to recover costs that the CPUC has authorized the Utility to pass on to customers, including costs to purchase electricity and natural gas, and to fund public purpose, demand response, and customer energy efficiency programs. In general, the revenue recognition criteria for pass-through costs billed to customers are met at the time the costs are incurred. The Utility records a regulatory balancing account asset or liability for differences between incurred costs and customer billings or authorized revenue meant to recover those costs, to the extent that these differences are probable of recovery or refund. As a result, these differences have no impact on net income.


	Year Ended December 31,
(in millions)		2023		2022		2021
Electric
Revenue from contracts with customers
Residential		$	6,041	$	6,130	$	6,089
Commercial		5,643		5,416		5,042
Industrial		1,784		1,626		1,493
Agricultural		1,413		1,830		1,565
Public street and highway lighting		83		77		73
Other, net (1)		136		(247)		(84)
Total revenue from contracts with customers - electric		15,100		14,832		14,178
Regulatory balancing accounts (2)		2,324		228		953
Total electric operating revenue		$	17,424	$	15,060	$	15,131

Natural gas
Revenue from contracts with customers
Residential		$	3,686	$	3,353	$	2,759
Commercial		1,052		1,005		713
Transportation service only		1,603		1,534		1,346
Other, net (1)		(145)		163		140
Total revenue from contracts with customers - gas		6,196		6,055		4,958
Regulatory balancing accounts (2)		808		565		553
Total natural gas operating revenue		7,004		6,620		5,511
Total operating revenues		$	24,428	$	21,680	$	20,642

PG&E Corporation and the Utility use the current expected credit loss model to estimate the expected lifetime credit loss on financial assets measured at amortized cost. PG&E Corporation and the Utility evaluate credit risk in their portfolio of financial assets quarterly. As of December 31, 2023, PG&E Corporation and the Utility identified the following significant categories of financial assets.

Trade receivables are represented by customer accounts. PG&E Corporation and the Utility record an allowance for doubtful accounts to recognize an estimate of expected lifetime credit losses. The allowance is determined on a collective basis based on the historical amounts written-off and an assessment of customer collectability. Furthermore, economic conditions are evaluated as part of the estimate of expected lifetime credit losses.

Expected credit losses of $636 million, $143 million, and $154 million were recorded in Operating and maintenance expense on the Consolidated Statements of Income for credit losses associated with trade and other receivables during the years ended December 31, 2023, 2022, and 2021, respectively. The portion of expected credit losses that are deemed probable of recovery are deferred to the RUBA, CPPMA, and a FERC regulatory asset. As of December 31, 2023, the RUBA current balancing accounts receivable balance was $507 million, and CPPMA and FERC noncurrent regulatory asset balances were $5 million and $78 million, respectively. As of December 31, 2022, the RUBA current balancing accounts receivable balance was $126 million, and CPPMA and FERC noncurrent regulatory asset balances were $3 million and $8 million, respectively.

Insurance receivables are related to the liability insurance policies PG&E Corporation and the Utility carry. Insurance receivable risk is related to each insurance carrier’s risk of defaulting on their individual policies. Wildfire Fund receivables are the funds available from the statewide fund established under AB 1054 for payment of eligible claims related to the 2021 Dixie fire that exceed $1.0 billion and available insurance coverage. For more information, see Note 14 below. Wildfire Fund receivables risk is related to the Wildfire Fund’s durability, which is a measurement of its claim-paying capacity. Lastly, PG&E Corporation and the Utility are required to determine if the fair value is below the amortized cost basis for their available-for-sale debt securities (i.e., impairment). If such an impairment exists and does not otherwise result in a write-down, then PG&E Corporation and the Utility must determine whether a portion of the impairment is a result of expected credit loss.

Inventories are carried at weighted-average cost and include gas stored underground, fuel oil, materials, and supplies. Natural gas stored underground is recorded to inventory when injected and then expensed as the gas is withdrawn for distribution to customers or to be used as fuel for electric generation. Materials and supplies are recorded to inventory when purchased and expensed or capitalized to plant, as appropriate, when consumed or installed.


	Estimated Service	Balance at December 31,
(in millions, except estimated service lives)	Lives (years)	2023		2022
Electricity generating facilities (1)	3 to 75	$	11,423	$	11,781
Electricity distribution facilities	10 to 70	45,205		41,061
Electricity transmission facilities	15 to 75	17,562		16,413
Natural gas distribution facilities	20 to 60	16,324		15,366
Natural gas transmission and storage facilities	5 to 70	10,496		9,859
General plant and other	5 to 50	9,165		8,518
Financing lease		787		18
Construction work in progress		4,452		4,137
Total property, plant, and equipment		115,414		107,153
Accumulated depreciation		(33,093)		(30,946)
Net property, plant, and equipment (2)		$	82,321	$	76,207

The Utility depreciates property, plant, and equipment using the composite, or group, method of depreciation, in which a single depreciation rate is applied to the gross investment balance in a particular class of property, with the exception of its securitized property, plant and equipment, which is depreciated over the life of the bond and a pattern consistent with principal payments. This method approximates the straight-line method of depreciation over the useful lives of property, plant, and equipment. The Utility’s composite depreciation rates were 3.56% in 2023, 3.74% in 2022, and 3.82% in 2021. The useful lives of the Utility’s property, plant, and equipment are authorized by the CPUC and the FERC, and the depreciation expense is recovered through rates charged to customers. Depreciation expense includes a component for the original cost of assets and a component for estimated cost of future removal, net of any salvage value at retirement. Upon retirement, the original cost of the retired assets, net of salvage value, is charged against accumulated depreciation. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to Operating and maintenance expense as incurred.

AFUDC represents the estimated cost of debt (i.e., interest) and equity funds used to finance regulated plant additions before they go into service and is capitalized as part of the cost of construction. AFUDC is recoverable through rates over the life of the related property once the property is placed in service. AFUDC related to the cost of debt is recorded as a reduction to interest expense. AFUDC related to the cost of equity is recorded in other income. The Utility recorded AFUDC related to debt and equity, respectively, of $82 million and $179 million during 2023, $81 million and $184 million during 2022, and $56 million and $133 million during 2021.

PG&E Corporation and the Utility account for an ARO at fair value in the period during which the legal obligation is incurred if a reasonable estimate of fair value and its settlement date can be made. At the time of recording an ARO, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. The Utility recognizes a regulatory asset or liability for the timing differences between the recognition of expenses and costs recovered through the ratemaking process. For more information, see Note 3 below.

The Utility has not recorded a liability related to certain AROs for assets that are expected to operate in perpetuity. As the Utility cannot estimate a settlement date or range of potential settlement dates for these assets, reasonable estimates of fair value cannot be made. As such, ARO liabilities are not recorded for retirement activities associated with substations, certain hydroelectric facilities; removal of lead-based paint in some facilities and certain communications equipment from leased property; and restoration of land to the conditions under certain agreements.

To estimate its liability, the Utility uses a discounted cash flow model based upon significant estimates and assumptions about future decommissioning costs, escalation rates, credit-adjusted risk-free rates, and the estimated date of decommissioning. For generation facilities, the Utility uses a probability-weighted, discounted cash flow model. For nuclear generation facilities, the model also considers multiple decommissioning start-year scenarios. The estimated future cash flows are discounted using a credit-adjusted risk-free rate that reflects the risk associated with the decommissioning obligation. The Utility performs detailed studies of its nuclear generation facilities every three years in conjunction with the NDCTP and updates its nuclear AROs accordingly, unless circumstances warrant more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility’s nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates; regulatory requirements; technology; and costs of labor, materials, and equipment. The Utility recovers its revenue requirements for decommissioning costs through rates through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered.

The ARO liability decreased from $5.9 billion as of December 31, 2022 to $5.5 billion as of December 31, 2023, primarily due to a decrease in nuclear decommissioning and hydroelectric facilities ARO. In the fourth quarter of 2023, the Utility recorded a downward revision to its hydroelectric facilities ARO of $205 million as a result of a revised decommissioning cost estimate.

The total nuclear decommissioning obligation was $4.0 billion as of December 31, 2023 compared to $4.1 billion as of December 31, 2022 based on the cost study performed as part of the 2021 NDCTP. As of December 31, 2023, the Utility recorded a $253 million downward adjustment to the nuclear decommissioning ARO to reflect the CPUC’s decision to approve Diablo Canyon’s extended operations until 2030 and the conditional award from the DOE’s Civil Nuclear Credit Program. See “U.S. DOE’s Civil Nuclear Credit Program” below. The Utility’s ARO could be materially impacted if the Utility does not receive the required federal and state licenses, permits, and approvals.

The Utility’s nuclear generation facilities consist of two units at Diablo Canyon and the Humboldt Bay independent spent fuel storage installation. Nuclear decommissioning requires the safe removal of a nuclear generation facility from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility’s nuclear decommissioning costs are recovered through rates and are held in trusts until authorized for release by the CPUC.

The Utility classifies its debt investments held in the nuclear decommissioning trusts as available-for-sale. Since the Utility’s nuclear decommissioning trust assets are managed by external investment managers, the Utility does not have the ability to sell its investments at its discretion. Therefore, all unrealized losses are considered other-than-temporary impairments. Gains or losses on the nuclear decommissioning trust investments are refundable to or recoverable from, respectively, customers through rates. Therefore, trust earnings are deferred and included in the regulatory liability for recoveries in excess of the ARO. There is no impact on the Utility’s earnings or accumulated other comprehensive income. The cost of debt and equity securities sold by the trust is determined by specific identification.

PG&E Corporation and the Utility received various government assistance programs during the years ended December 31, 2023 and 2022. PG&E Corporation’s and the Utility’s accounting policy is to apply a grant accounting model by analogy to International Accounting Standards 20, Accounting for Government Grants and Disclosure of Government Assistance.

On June 30, 2022, AB 180 became law. AB 180 authorized the DWR to use up to $75 million to support contracts with the owners of electric generating facilities pending retirement, such as Diablo Canyon, to fund, reimburse or compensate the owner for any costs, expenses or financial commitments incurred to retain the future availability of such generating facilities pending further legislation. The resulting agreement between DWR and the Utility was effective beginning October 1, 2022, and will continue until full disbursement of funds or termination per the agreement. In the event of a termination, the Utility will take reasonable steps to end activities associated with this agreement and will return to DWR any unused funds. During the years ended December 31, 2023 and 2022, the Consolidated Statements of Income reflected $56 million and $0 million, respectively, recorded as a deduction to Cost of electricity for income related to government grants for incurred eligible costs to purchase nuclear fuel.

On October 18, 2022, the DWR and the Utility executed a $1.4 billion loan agreement to support the extension of Diablo Canyon, up to approximately $1.1 billion of which could be repaid by funds received from the DOE (see “U.S. DOE’s Civil Nuclear Credit Program” below). Under the loan agreement, the DWR pays the Utility a monthly performance-based disbursement equal to $7 for each MWh generated by Diablo Canyon, effective September 2, 2022. The Utility may use the proceeds of the performance-based disbursements for any business purpose, except as profits or dividends to shareholders or as otherwise prohibited by SB 846. The Utility began earning performance-based disbursements beginning on September 2, 2022 and is eligible to earn performance-based disbursements until the previously-approved retirement dates for Diablo Canyon Unit 1 and Unit 2 (2024 and 2025, respectively). The performance-based disbursements are contingent upon the Utility’s ongoing efforts to pursue extension of and continued safe and reliable operation of Diablo Canyon. The aggregate amount of performance-based disbursements under this agreement will not exceed $300 million.

The Utility initially accounts for all disbursements from the DWR loan agreement pursuant to ASC 470, Debt. When there is reasonable assurance that the Utility will have loan disbursements forgiven by the DWR, such as when the Utility earns a performance-based disbursement or when funds expected to be received from the DOE are less than incurred eligible costs to support the extension of Diablo Canyon, the Utility will recognize those forgiven loans as income related to government grants. The Utility records the income related to government grants as a deduction to expense in the same period(s) that eligible costs are incurred.


(in millions)	2023		2022
Long-term debt:
DWR Loan Outstanding at January 1	$	312	$	—

Proceeds received (1)	—		350

Operating Expenses:
Operating and maintenance expense - Performance-based disbursements	(124)		(38)
Operating and maintenance expense - Loan forgiven	(90)		—
Total deduction to Operating Expenses	(214)		(38)

Long-term debt:
DWR Loan Outstanding at December 31	$	98	$	312

On January 11, 2024, the Utility and DOE entered into a Credit Award and Payment Agreement for up to $1.1 billion related to Diablo Canyon as part of the DOE’s Civil Nuclear Credit Program. The Utility will use these funds to repay its loans outstanding under the DWR Loan Agreement (see “DWR Loan Agreement” above). Final award amounts will be determined following completion of each year of the award period, and amounts awarded over a four-year award period ending in 2026 will be based on a number of factors, including actual costs incurred to extend the Diablo Canyon operations. When there is reasonable assurance that the Utility will receive funding and comply with the conditions of the DOE’s Civil Nuclear Credit Program, the Utility will recognize such funding as income and will record a receivable related to government grants. During the year ended December 31, 2023, the Consolidated Statements of Income reflected $76 million and $115 million as deductions to Cost of electricity and Operating and maintenance expense, respectively, for income related to government grants for incurred fuel costs and incurred eligible costs to support the extension of Diablo Canyon.

A VIE is an entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, or whose equity investors lack any characteristics of a controlling financial interest. An enterprise that has a controlling financial interest in a VIE is a primary beneficiary and is required to consolidate the VIE.

The SPV was created in connection with the Receivables Securitization Program and is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the Receivables Securitization Program, the Utility sells certain of its receivables and certain related rights to payment and obligations of the Utility with respect to such receivables, and certain other related rights to the SPV, which, in turn, obtains loans secured by the receivables from financial institutions (the “Lenders”). The pledged receivables and the corresponding debt are included in Accounts receivable, Accrued unbilled revenue, Other noncurrent assets, and Long-term debt on the Consolidated Balance Sheets.

The SPV is considered a VIE because its equity capitalization is insufficient to support its activities. The most significant activities that impact the economic performance of the SPV are decisions made to manage receivables. The Utility is considered the primary beneficiary and consolidates the SPV as it makes these decisions. No additional financial support was provided to the SPV during the year ended December 31, 2023 or is expected to be provided in the future that was not previously contractually required. As of December 31, 2023 and December 31, 2022, the SPV had net accounts receivable of $2.7 billion and $3.6 billion, respectively, and outstanding borrowings of $1.5 billion and $1.2 billion, respectively, under the Receivables Securitization Program. For more information, see Note 4 below.

PG&E Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing orders for the first and second AB 1054 securitization transactions, the Utility sold its right to receive revenues from the non-bypassable wildfire hardening fixed recovery charges (“Recovery Property”) to PG&E Recovery Funding LLC, which, in turn, issued two separate series of recovery bonds secured by separate Recovery Property.

PG&E Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Recovery Funding LLC are decisions made by the servicer of the Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Recovery Funding LLC during the year ended December 31, 2023 or is expected to be provided in the future that was not previously contractually required. On November 12, 2021, PG&E Recovery Funding LLC issued approximately $860 million of Senior Secured Recovery Bonds. On November 30, 2022, PG&E Recovery Funding LLC issued approximately $983 million of Series 2022-A Senior Secured Recovery Bonds. As of December 31, 2023 and December 31, 2022, PG&E Recovery Funding LLC had outstanding borrowings of $1.8 billion, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets.

PG&E Wildfire Recovery Funding LLC is a bankruptcy remote, limited liability company wholly owned by the Utility, and its assets are not available to creditors of PG&E Corporation or the Utility. Pursuant to the financing order for the first and second SB 901 securitization transactions, the Utility sold its right to receive revenues from the non-bypassable fixed recovery charges (“SB 901 Recovery Property”) to PG&E Wildfire Recovery Funding LLC, which, in turn, issued two separate series of recovery bonds secured by separate SB 901 Recovery Property.

PG&E Wildfire Recovery Funding LLC is considered a VIE because its equity capitalization is insufficient to support its operations. The most significant activities that impact the economic performance of PG&E Wildfire Recovery Funding LLC are decisions made by the servicer of the SB 901 Recovery Property. The Utility is considered the primary beneficiary and consolidates PG&E Wildfire Recovery Funding LLC as it acts in this role as servicer. No additional financial support was provided to PG&E Wildfire Recovery Funding LLC during the year ended December 31, 2023 or is expected to be provided in the future that was not previously contractually required. On May 10, 2022, PG&E Wildfire Recovery Funding LLC issued $3.6 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-A Recovery Bonds”). On July 20, 2022, PG&E Wildfire Recovery Funding LLC issued $3.9 billion aggregate principal amount of senior secured recovery bonds (the “Series 2022-B Recovery Bonds”). As of December 31, 2023 and December 31, 2022, PG&E Wildfire Recovery Funding LLC had outstanding borrowings of $7.3 billion and $7.5 billion, respectively, included in Long-term debt and Long-term debt, classified as current on the Consolidated Balance Sheets. For more information, see Note 5 below.

Some of the counterparties to the Utility’s power purchase agreements are considered VIEs. Each of these VIEs was designed to own a power plant that would generate electricity for sale to the Utility. To determine whether the Utility was the primary beneficiary of any of these VIEs as of December 31, 2023, it assessed whether it absorbs any of the VIE’s expected losses or receives any portion of the VIE’s expected residual returns under the terms of the power purchase agreement, analyzed the variability in the VIE’s gross margin, and considered whether it had any decision-making rights associated with the activities that are most significant to the VIE’s performance, such as dispatch rights or operating and maintenance activities. The Utility’s financial obligation is limited to the amount the Utility pays for delivered electricity and capacity. The Utility did not have any decision-making rights associated with any of the activities that are most significant to the economic performance of any of these VIEs. Since the Utility was not the primary beneficiary of any of these VIEs as of December 31, 2023, it did not consolidate any of them.

BA2 300 Lakeside LLC is considered a VIE because the group that holds the equity investment at risk lacks the right to receive the expected residual returns of the entity due to a fixed-price purchase option covering more than 50% of the fair value of the assets held by the entity. The most significant activities that impact the economic performance of BA2 300 Lakeside LLC are decisions related to significant maintenance and remarketing of the property. The Utility is not considered the primary beneficiary and does not consolidate BA2 300 Lakeside LLC as it does not have any decision-making rights associated with these activities. The Utility’s financial obligation is limited to the issued letter of credit as well as the amounts it pays for base rent and certain costs, per the office lease agreement. For more information, see “Recognition of Lease Assets and Liabilities” below.

PG&E Corporation and the Utility account for contributions to the Wildfire Fund by capitalizing an asset, amortizing to periods ratably based on an estimated period of coverage, and incrementally adjusting for accelerated amortization as the level of coverage declines, as further described below. However, AB 1054 did not specify a period of coverage for the Wildfire Fund; therefore, this accounting treatment is subject to significant accounting judgments and estimates. Since the inception of the Wildfire Fund, PG&E Corporation and the Utility have estimated a period of coverage of 15 years. In estimating the period of coverage, PG&E Corporation and the Utility used a dataset of historical, publicly available fire-loss data caused by electrical equipment to create Monte Carlo simulations of expected loss. The number of years of historic fire-loss data and the effectiveness of mitigation efforts by the California electric utility companies are significant assumptions used to estimate the period of coverage. Other assumptions include the estimated costs to settle wildfire claims for participating electric utilities including the Utility, the CPUC’s determinations of whether costs were just and reasonable in cases of electric utility-caused wildfires and amounts required to be reimbursed to the Wildfire Fund, the impacts of climate change, the amount of future insurance coverage held by the electric utilities, the FERC-allocable portion of loss recovery, and the future transmission and distribution equity rate base growth of participating electric utilities. These assumptions create a high degree of uncertainty for the estimated useful life of the Wildfire Fund.

PG&E Corporation and the Utility re-evaluate the estimated period of coverage annually and as required by additional information. Changes in any of the assumptions could materially impact the estimated period of coverage. PG&E Corporation and the Utility assess the Wildfire Fund asset for acceleration of the amortization of the asset in the event that it is probable that a participating utility’s electrical equipment will be found to be the substantial cause of a catastrophic wildfire.

As of December 31, 2023, PG&E Corporation and the Utility recorded $193 million in Other current liabilities, $750 million in Other noncurrent liabilities, $450 million in Current assets - Wildfire Fund asset, and $4.3 billion in Noncurrent assets - Wildfire Fund asset in the Consolidated Balance Sheets. During the year ended December 31, 2023 and 2022, the Utility recorded amortization and accretion expense of $567 million and $477 million, respectively. The amortization of the asset, accretion of the liability, and applicable acceleration of the amortization of the asset is reflected in Wildfire Fund expense in the Consolidated Statements of Income. As of December 31, 2023, PG&E Corporation and the Utility recorded $325 million and $275 million in Accounts receivable - other and Other noncurrent assets, respectively, for Wildfire Fund receivables related to the 2021 Dixie fire.


(in millions, net of income tax)	Pension Benefits		Other Benefits		Customer Credit Trust		Total
Beginning balance	$	(12)	$	18	$	(6)	$	—
Other comprehensive income before reclassifications:
Unrealized gain on investments (net of taxes of $0, $0 and $3, respectively)	—		—		8		8
Unrecognized net actuarial gain (loss) (net of taxes of $76, $28 and $0, respectively)	(196)		73		—		(123)
Regulatory account transfer (net of taxes of $70, $28 and $0, respectively)	180		(73)		—		107
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (credit) (net of taxes of $1, $1 and $0, respectively) (1)	(3)		2		—		(1)
Amortization of net actuarial (gain) loss (net of taxes of $0, $5 and $0, respectively) (1)	1		(14)		—		(13)
Regulatory account transfer (net of taxes of $1, $4 and $0, respectively) (1)	2		12		—		14
Net current period other comprehensive income (loss)	(16)		—		8		(8)
Ending balance	$	(28)	$	18	$	2	$	(8)


(in millions, net of income tax)	Pension Benefits		Other Benefits		Customer Credit Trust		Total
Beginning balance	$	(33)	$	18	$	—	$	(15)
Other comprehensive income before reclassifications:
Unrealized loss on investments (net of taxes of $0, $0 and $3, respectively)	—		—		(6)		(6)
Unrecognized net actuarial gain (loss) (net of taxes of $102, $99 and $0, respectively)	263		(255)		—		8
Regulatory account transfer (net of taxes of $94, $99 and $0, respectively)	(242)		255		—		13
Amounts reclassified from other comprehensive income:
Amortization of prior service cost (credit) (net of taxes of $1, $2 and $0, respectively) (1)	(3)		5		—		2
Amortization of net actuarial (gain) loss (net of taxes of $1, $11 and $0, respectively)(1)	1		(29)		—		(28)
Regulatory account transfer (net of taxes of $0, $9 and $0, respectively) (1)	2		24		—		26
Net current period other comprehensive income (loss)	21		—		(6)		15
Ending balance	$	(12)	$	18	$	(6)	$	—

A lease exists when an arrangement allows the lessee to control the use of an identified asset for a stated period in exchange for payments. This determination is made at inception of the arrangement. All leases must be recognized as a ROU asset and a lease liability on the balance sheet of the lessee. The ROU asset reflects the lessee’s right to use the underlying asset for the lease term, and the lease liability reflects the obligation to make the lease payments. PG&E Corporation and the Utility have elected not to separate lease and non-lease components.

The Utility estimates the ROU assets and lease liabilities at net present value using its incremental secured borrowing rates unless the implicit discount rate in the leasing arrangement can be ascertained. The incremental secured borrowing rate is based on observed market data and other information available at the lease commencement date. The ROU assets and lease liabilities only include the fixed lease payments for arrangements with terms greater than 12 months. These amounts are presented within the supplemental disclosures of noncash activities on the Consolidated Statement of Cash Flows. Renewal and termination options only impact the lease term if it is reasonably certain that they will be exercised. PG&E Corporation recognizes lease expense on a straight-line basis over the lease term. The Utility recognizes lease expense in conformity with ratemaking.

Financing leases are included in financing lease ROU assets and current and noncurrent financing lease liabilities on the Consolidated Balance Sheets. For the year ended December 31, 2023, the Utility made total fixed cash payments of $142 million for financing leases, which were included in the measurement of financing lease liabilities and are presented within financing activities on the Consolidated Statement of Cash Flows. Any variable lease payments for financing leases are included in operating activities on the Consolidated Statement of Cash Flows. Financing leases were immaterial for the year ended December 31, 2022. The majority of the Utility’s financing lease ROU assets and lease liabilities relate to the Oakland Headquarters lease discussed below.

On October 23, 2020, the Utility and BA2 300 Lakeside LLC (“Landlord”), a wholly owned subsidiary of TMG Bay Area Investments II, LLC, entered into an office lease agreement for approximately 910,000 rentable square feet of space within the Lakeside Building to serve as the Utility’s principal administrative headquarters (the “Lease”). In connection with the Lease, the Utility also issued to Landlord (i) an option payment letter of credit in the amount of $75 million, and (ii) a lease security letter of credit in the amount of $75 million. The term of the Lease began on April 8, 2022.

On July 11, 2023, the Utility and the Landlord entered into an Amendment to Office Lease and an Agreement of Purchase and Sale and Joint Escrow Instructions, pursuant to which the Utility was deemed to have exercised its option to purchase the Property, as modified. Pursuant to the Purchase and Sale and Joint Escrow Instructions, the purchase price of the Property will be $906 million, with deposits applicable to such purchase price of $150 million paid by July 11, 2023, $250 million to be paid on or before July 11, 2024, and the remaining $506 million to be paid at closing in June 2025. Additionally, the $75 million option payment letter of credit was returned to the Utility. The Utility will also receive a credit of approximately $172 million towards the final payment, subject to adjustments, which represents the estimated outstanding principal balance of a loan carried by the Property that will be assigned to, and assumed by, the Utility at closing. The Utility will continue to lease the Property pursuant to the Lease, as amended, until closing.

As of December 31, 2023, the Utility has recorded $787 million in Financing lease ROU assets, $108 million in accumulated amortization, $218 million in leasehold improvements, net of accumulated amortization, which includes $134 million that was provided to the Utility as lease incentives, $259 million in current Financing lease liabilities, and $554 million in noncurrent Financing lease liabilities in the Consolidated Financial Statements primarily related to the Lease, as amended.

Operating leases are included in operating lease ROU assets and current and noncurrent Operating lease liabilities on the Consolidated Balance Sheets. For the years ended December 31, 2023 and 2022, the Utility made total cash payments, including fixed and variable, of $1.9 billion and $2.3 billion, respectively, for operating leases which are presented within operating activities on the Consolidated Statement of Cash Flows.

The majority of the Utility’s operating lease ROU assets and lease liabilities relate to various power purchase agreements. These power purchase agreements primarily consist of generation plants leased to meet customer demand plus applicable reserve margins. Operating lease variable costs include amounts from renewable energy power purchase agreements where payments are based on certain contingent external factors such as wind, hydro, solar, biogas, and biomass power generation. See “Third-Party Power Purchase Agreements” in Note 15 below.

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which amends the existing guidance to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant segment expenses. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Tax Disclosures, which amends the existing guidance to enhance the transparency and decision usefulness of income tax disclosures. The standard requires consistent categories and greater disaggregation of information in the rate reconciliation, and income taxes paid disaggregated by jurisdiction. This ASU will become effective for PG&E Corporation and the Utility for fiscal years beginning after December 15, 2024. PG&E Corporation and the Utility are currently evaluating the impact the guidance will have on their Consolidated Financial Statements and related disclosures.